A seismic survey represents an attempt to image or map the subsurface of the earth by sending sound energy down into the ground and recording the “echoes” that return from the rock layers below. The source of the down-going sound energy might come, for example, from explosions or seismic vibrators on land, or air guns in marine environments. During a seismic survey, the energy source is placed at various locations near the surface of the earth above a geologic structure of interest. Each time the source is activated, it generates a seismic signal that travels downward through the earth, is reflected, and, upon its return, is recorded at a great many locations on the surface. Multiple source/recording combinations are then combined to create a near continuous profile of the subsurface that can extend for many miles. In a two-dimensional (2D) seismic survey, the recording locations are generally laid out along a single line, whereas in a three dimensional (3D) survey the recording locations are distributed across the surface in a grid pattern. In simplest terms, a 2D seismic line can be thought of as giving a cross sectional picture (vertical slice) of the earth layers as they exist directly beneath the recording locations. A 3D survey produces a data “cube” or volume that is, at least conceptually, a 3D picture of the subsurface that lies beneath the survey area. In reality, though, both 2D and 3D surveys interrogate some volume of earth lying beneath the area covered by the survey.
A seismic survey is composed of a very large number of individual seismic recordings or traces. In a typical 2D survey, there will usually be several tens of thousands of traces, whereas in a 3D survey the number of individual traces may run into the multiple millions of traces. Chapter 1, pages 9-89, of Seismic Data Processing by Ozdogan Yilmaz, Society of Exploration Geophysicists, 1987, contains general information relating to conventional 2D processing and that disclosure is incorporated herein by reference. General background information pertaining to 3D data acquisition and processing may be found in Chapter 6, pages 384-427, of Yilmaz, the disclosure of which is also incorporated herein by reference.
A seismic trace is a digital recording of the acoustic energy reflecting from inhomogeneities or discontinuities in the subsurface, a partial reflection occurring each time there is a change in the elastic properties of the subsurface materials. The digital samples are usually acquired at 0.002 second (2 millisecond or “ms”) intervals, although 4 millisecond and 1 millisecond sampling intervals are also common. Each discrete sample in a conventional digital seismic trace is associated with a discrete sampling of the reflected acoustic wavefield in time. Many variations of the conventional source-receiver arrangement are used in practice, e.g. VSP (vertical seismic profiles) surveys, ocean bottom surveys, etc. Further, the surface location of every trace in a seismic survey is carefully tracked and is generally made a part of the trace itself (as part of the trace header information). This allows the seismic information contained within the traces to be later correlated with specific surface and subsurface locations, thereby providing a means for posting and contouring seismic data—and attributes extracted therefrom—on a map (i.e., “mapping”).
The data in a 3D survey are amenable to viewing in a number of different ways. First, horizontal “constant time slices” may be taken extracted from a stacked or unstacked seismic volume by collecting all of the digital samples that reflect from a given subsurface location after correcting these samples for the effects of acoustic propagation. This operation results in a horizontal 2D plane of seismic data. By animating a series of 2D planes it is possible for the interpreter to pan through the volume, giving the impression that successive layers are being stripped away so that the information that lies underneath may be observed. Similarly, a vertical plane of seismic data may be taken at an arbitrary azimuth through the volume by collecting and displaying the seismic traces that lie along a particular line. This operation, in effect, extracts an individual 2D seismic line from within the 3D data volume. It should also be noted that a 3D dataset can be thought of as being made up of a 5D data set that has been reduced in dimensionality by stacking it into a 3D image. The dimensions are typically time (or depth “z”), “x” (e.g., North-South), “y” (e.g., East-West), source-receiver offset in the x direction, and source-receiver offset in the y direction. While the examples here may focus on the 2D and 3D cases, the extension of the process to four or five dimensions is straightforward.
Seismic data that have been properly acquired and processed can provide a wealth of information to the explorationist, one of the individuals within an oil company whose job it is to locate potential drilling sites. For example, a seismic profile gives the explorationist a broad view of the subsurface structure of the rock layers and often reveals important features associated with the entrapment and storage of hydrocarbons such as faults, folds, anticlines, unconformities, and sub-surface salt domes and reefs, among many others. During the computer processing of seismic data, estimates of subsurface rock velocities are routinely generated and near surface inhomogeneities are detected and displayed. In some cases, seismic data can be used to directly estimate rock porosity, water saturation, and hydrocarbon content. Less obviously, seismic waveform attributes such as phase, peak amplitude, peak-to-trough ratio, and a host of others, can often be empirically correlated with known hydrocarbon occurrences and that correlation applied to seismic data collected over new exploration targets.
Many variations of the conventional source-receiver arrangement are used in practice, e.g. VSP (vertical seismic profile) surveys, ocean bottom surveys, etc.
Seismic attributes such as amplitude versus offset (“AVO”) or amplitude versus angle of incidence (“AVA”) analyses can yield important information about the contents of subsurface rock formations. Although hydrocarbons cannot generally be viewed directly in the subsurface using seismic, variations in reflectivity with angle of incidence have been increasingly used as an attribute or indicator of the presence of subsurface gas. See, for example, Castagna and Swan, “Principles of AVO Crossplotting”, The Leading Edge, April 1997, the disclosure of which is incorporated herein by reference. However, deeper targets pose a number of problems for this technology, not the least of which is related to the distortion that may be introduced by the subsurface structure and/or the processing methods that are used to image that structure.
One of the key aspects in the continuing development of these areas of complex geology is well planning, which often must be done in geologic settings where obtaining good seismic images can be a challenge. Since AVA is often used to assess the potential for well location, any irregularities in AVA response due to uneven acoustic illumination resulting from complex overburden introduces substantial risk in AVA analysis and could very well adversely effect well placement.
Subsurface imaging in regions of complex structure is problematic because the seismic wavefield may be distorted significantly as it passes through such complexity. Of particular interest for purpose of the instant disclosure is imaging in the presence of subsurface salt. Seismic surveys that include subsurface salt features (e.g., salt domes) can produce data that is marred by uneven illumination of the reflectors below the salt (or other structure). This in turn, can cause AVA-type analyses to be difficult to interpret and/or simply unreliable. In the case of a salt dome, the distortion in the wavefield is caused by the large velocity contrast between salt and the surrounding rock (i.e., salt typically has a seismic velocity that is much higher than that of the surrounding sedimentary rocks). This velocity contrast results in large amounts of ray bending and rays that are normal to the target reflector will tend to go critical at the sediment salt interface. Conventional seismic imaging methods do not properly compensate for this uneven illumination, which can distort the observed trace amplitudes and can render AVO/AVA analysis unreliable.
Thus, what is needed is a method of compensating seismic gathers for illumination irregularities caused by structure, the effects of the acquisition footprint, and wave propagation effects in complex structural areas while simultaneously preserving the AVA reflectivity signature.
Heretofore, as is well known in the seismic processing and seismic interpretation arts, there has been a need for a method of obtaining better estimates of the AVA effect in areas with a complex geological subsurface structure. Accordingly, it should now be recognized, as was recognized by the present inventor, that there exists, and has existed for some time, a very real need for a method of seismic data processing that would address and solve the above-described problems.
Before proceeding to a description of the present invention, however, it should be noted and remembered that the description of the invention which follows, together with the accompanying drawings, should not be construed as limiting the invention to the examples (or preferred embodiments) shown and described. This is so because those skilled in the art to which the invention pertains will be able to devise other forms of this invention within the ambit of the appended claims.